SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

Commission file number 000-25717

PETROHAWK ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

1100 Louisiana, Suite 4400, Houston, Texas 77002

(Address of principal executive offices including ZIP code)

(832) 204-2700

(Registrant’s telephone number)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.                 Yes ý      No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K  o.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

Yes o       No ý

The aggregate market value of Common Stock, par value $.001 per share (Common Stock), held by non-affiliates (based upon the closing sales price on the NASDAQ National Market on June 30, 2004), the last business day of registrant’s most recently completed second fiscal quarter was approximately $40,760,820.

As of March 30, 2005, there were 40,087,954 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be filed on or before April 30, 2005 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements.  The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements.  These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, and other factors detailed in this document and in our other Securities and Exchange Commission (SEC) filings.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document.

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PART I

ITEM 1.           BUSINESS

Overview

Petrohawk Energy Corporation (Petrohawk or the Company), a Delaware corporation, is an independent oil and gas company engaged in the acquisition, development, production and exploration of natural gas and oil properties located in North America.  We were formed in June 1997 as a Nevada corporation and were reincorporated in the state of Delaware during 2004.  Our properties are concentrated in the Anadarko, South Texas, Permian Basin, East Texas, Arkoma and Gulf Coast regions.

At December 31, 2004, our estimated total proved oil and gas reserves were approximately 219 Bcfe, consisting of 9.7 million barrels of oil and 160.9 Bcf of natural gas.  Proved reserves are approximately 73% gas on an equivalent basis and approximately 78% were classified as proved developed.  Year-end prices used to determine proved reserves were $40.25 per barrel of oil and $6.18 per Mmbtu of gas.

We have increased our proved reserves and production principally through acquisitions. We focus on properties within our core operating areas that have a significant proved reserve component and which management believes have additional development and exploration opportunities.

Recent Developments

We have recently completed several transactions:

Proton Oil & Gas Corporation

On February 25, 2005, we completed the purchase of Proton Oil & Gas Corporation (Proton) for approximately $53 million.  This privately negotiated transaction included estimated proved reserves of approximately 28 Bcfe and had an economic effective date of January 1, 2005.  The Proton properties are located in South Louisiana and South Texas.  Additional transaction highlights include the following estimates:

•                  5.0 Mmcfe of production per day

•                  46% natural gas

•                  47% proved developed

•                  97% operated

•                  15 year reserves-to-production ratio

Major properties in the asset base include interests in the Gueydan Field in Vermilion Parish, Louisiana, with 16 Bcfe of estimated proved reserves, 1,018 gross acres and nine PUD locations. In South Texas, significant properties include interests in the Heard Ranch Field in Bee County, Texas with approximately 7 Bcfe of estimated proved reserves, 4,230 gross acres and fifteen Proved Undeveloped (PUD) locations. The acquisition also included 3-D seismic data covering all major properties.

Sale of Royalty Interest Properties

On February 25, 2005, we completed the disposition of certain royalty interest properties previously acquired from Wynn-Crosby to Noble Royalties, Inc. (Noble) d/b/a Brown Drake Royalties for approximately $80 million in cash. We sold estimated proved reserves of approximately 26 Bcfe with current estimated production of approximately 5.0 Mmcfe per day.

Wynn-Crosby Transaction

On November 23, 2004, we acquired Wynn-Crosby Energy, Inc. and eight of the limited partnerships it managed (Wynn-Crosby) for a purchase price of approximately $425 million. The transaction was funded with proceeds from a $200 million private equity placement, $210 million in borrowings from our commercial bank group, and cash.

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In connection with the acquisition, Netherland, Sewell & Associates, Inc., our independent petroleum engineering consultants (Netherland, Sewell), evaluated the proved reserves associated with working interest properties, and our reserve engineers evaluated proved reserves associated with royalty interest properties, resulting in approximately 200 Bcfe of total estimated proved reserves at July 1, 2004, the effective date of the transaction. At December 31, 2004, Wynn-Crosby had estimated proved reserves of approximately 190 Bcfe of which 74% and 26% were related to natural gas and oil, respectively.  Approximately 76% were classified as proved developed.

The properties we acquired are primarily located in the South Texas, East Texas, Anadarko, Arkoma and Permian Basin regions and include approximately 75,000 net undeveloped acres in the Arkoma Basin region, as well as what we believe to be significant exploration opportunities in South Louisiana, South Texas and the Anadarko Basin.

Major properties in the Wynn-Crosby asset base include interests in La Reforma, a significant Vicksburg formation field in South Texas, the Dry Hollow and Provident City fields in the Wilcox trend of Lavaca County, Texas, and the Los Indios, Nabors, Ann Mag and McAllen Ranch fields in South Texas. In the East Texas basin, significant properties include interests in the South Carthage, North Beckville and Blocker fields. Other key properties include interests in the Waddell Ranch, Teague and ROC fields in the Permian Basin, the Kinta, Cedars, and Pine Hollow fields in the Arkoma Basin and the Lipscomb and Eakly-Weatherford fields in the Anadarko Basin.

PHAWK, LLC Transaction

On August 11, 2004, we acquired from PHAWK, LLC certain oil and gas properties in the Breton Sound area, Plaquemines Parish, Louisiana and in the West Broussard field in Lafayette Parish, Louisiana having approximately 2.9 Bcfe of estimated proved reserves. This purchase included the acquisition of 79 square miles of recently reprocessed 3-D seismic data and a 25% working interest in eight leased drilling prospects covering 2,528 gross acres in the Breton Sound/Main Pass area as well as two producing wells, pipelines and associated production facilities in Breton Sound Blocks 11 and 23. A 14% working interest (approximately 10% net revenue interest) was acquired in the Montesano #1 well in the West Broussard field. The Montesano #1 well was placed on production in August 2004. The purchase price for all of the proved reserves, seismic data, undeveloped acreage, pipelines, production facility and other assets was $8.5 million in cash. The effective date of the acquisition was June 1, 2004 and the effects of this transaction were first reported in our results for the quarter ended September 30, 2004.

Recapitalization by PHAWK, LLC

On May 25, 2004, PHAWK, LLC (PHAWK) (formerly known as Petrohawk Energy, LLC), which is owned by affiliates of EnCap Investments, L.P., Liberty Energy Holdings LLC, Floyd C. Wilson and other members of the Company’s management, recapitalized the Company with $60 million in cash.  The $60 million investment was structured as the purchase by PHAWK of 7.576 million new shares of our common stock for $25 million, a $35 million five-year 8% subordinated note convertible into approximately 8.75 million shares of common stock and warrants to purchase 5.0 million shares of our common stock at a price of $3.30 per share. At the annual stockholders meeting held July 15, 2004, the stockholders approved changing the name of the Company to Petrohawk Energy Corporation (from Beta Oil & Gas, Inc.), reincorporating the company in Delaware, and the adoption of new stock option plans.  Since the Company and PHAWK, LLC are under common control, the assets were recorded by the Company at the net book value of PHAWK, LLC at the time of the sale.  The purchase price exceeded the net book value by approximately $5.6 million.  The excess is reflected as a return of capital to PHAWK, LLC in the financial statements.

A special committee of one disinterested director was formed by the Company’s board of directors to evaluate, negotiate and complete the purchase.  The Special Committee hired an independent reservoir engineering firm to provide a reserve evaluation and engaged an independent financial advisor to evaluate the fairness, from a financial point of view, to the Company.  The independent financial advisor has rendered a fairness opinion to the Special Committee.

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Business Strategy

We are an independent oil and gas company engaged in the acquisition, development, production and exploration of natural gas and oil properties located in North America.   Our primary objective is to increase shareholder value.  To accomplish this objective, our business strategy is focused on the following:

•                  Pursuit of Strategic Acquisitions.  We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects.  We seek to acquire operational control of properties that we believe have significant exploitation and exploration potential.  Our strategy includes a significant focus on increasing our holdings in fields and basins in which we already own an interest.

•                  Further Development of Existing Properties.  We seek to add proved reserves and increase production through the use of advanced technologies, including detailed reservoir engineering analysis, drilling development wells utilizing sophisticated techniques and selectively recompleting existing wells.  We believe our properties have substantial additional reserve potential and we plan to drill step-out wells to expand known field limits.  We intend to enhance the cost efficiency and quality control of these activities by operating the majority of our properties.  We believe that many of the properties included in the Wynn-Crosby acquisition have significant development potential and in certain cases have not been actively developed in the past.

•                  Growth Through Exploration.  We intend to conduct an active technology-driven exploration program that is designed to complement our property acquisition and development drilling activities with moderate to high risk exploration projects that have greater reserve potential.  We generate exploration prospects through the analysis of geological and geophysical data and the interpretation of 3-D seismic data.  We intend to manage our exploration risk and expenditures through the optimal scheduling of our drilling program and by selectively reducing our capital exposure in certain exploratory prospects through sales of interests to industry partners.

•                  Property Portfolio Management.  We continually evaluate our property base to identify opportunities to divest higher cost, less productive properties with limited development potential.  This rationalization strategy, if successful, will allow our technical staff to more efficiently focus their efforts on a portfolio of core properties with significant potential to increase our proved reserves and production.  We also seek to increase the number of fields we operate as a percentage of our total properties through our property management strategy, as evident with the recent sale of the royalty properties that were acquired from Wynn-Crosby.

•                  Maintenance of Financial Flexibility.  We intend to maintain substantial unused borrowing capacity under our bank revolving credit facility by periodically refinancing our bank debt in the capital markets when conditions are favorable.  A significant part of our financial management strategy will involve the use of hedges to secure product prices for a substantial portion of our expected production.  We believe our expanded base of internally generated cash flow and other information resources will provide us with the financial flexibility to pursue additional acquisitions of producing properties and leasehold acreage and to develop our project inventory in an optimal fashion.

•                  Benefit from the Transactional Nature of Our Industry.  The independent exploration and production industry has been consolidating for a number of years.  Our business strategy embraces this trend.  We intend to assemble a portfolio of quality proved reserves and drilling opportunities within a core group of operated properties that may potentially be desirable as a strategic acquisition target by larger industry participants.  Our management team has significant and successful experience in starting, building and selling companies in this industry sector.

Natural Gas and Crude Oil Reserves

The December 31, 2004 proved reserve estimates presented here were prepared by Netherland, Sewell with the exception of 26.2 Bcfe of proved reserves associated with royalty interest properties acquired from Wynn-Crosby and subsequently sold on February 25, 2005 which were not part of Netherland, Sewell’s report.  For additional information regarding estimates of proved reserves, the review of such estimates by Netherland, Sewell and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8.  Our reserves are sensitive to natural gas and crude oil sales prices and their effect on economic producing rates. Our reserves are based on oil and gas index prices in effect on the last day of December 2004.

There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control, such as commodity pricing. Therefore, the reserve information in this Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately

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recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.

The following table presents certain information as of December 31, 2004 and includes the recently acquired PHAWK and Wynn-Crosby properties, all as of the periods indicated above. We acquired the PHAWK properties in August 2004 and the Wynn-Crosby properties in November 2004. Shut-in wells currently not capable of production are excluded from the producing well information.

(1)           Reserve Life Index is equal to year-end reserves divided by estimated annual production.               

(2)           The term net as used in net production throughout this document refers to amounts that include only

acreage or production that is owned by Petrohawk Energy Corporation and produced to its interest, less royalties and production due to others. Net Wells represents our working interest share of each well.

(3)           Includes the impact of non-operated royalty properties. Excluding royalty interest properties, our total percent proved reserves operated is 51%.

Anadarko Basin.    The West Edmond Hunton Lime Unit (WEHLU) is our largest property in this region, covering 30,000 acres (approximately 47 square miles) primarily in Oklahoma County, Oklahoma. The WEHLU field, originally discovered in 1942, is the largest Hunton Lime formation field in the state of Oklahoma. The field has 58 oil and natural gas wells (28 currently producing) with stable production holding the entire unit. We own a 98% working interest at WEHLU and currently operate the field. We have an agreement with Avalon Exploration, Inc. of Tulsa, Oklahoma to jointly develop additional reserves and production in WEHLU. The area of mutual interest created by our agreement with Avalon covers 5,680 acres located in the central-northwest area of the field.

Other significant properties in this area include interests in the Lipscomb field in Lipscomb County, Texas where our working interests range from 75% to 100% and the Eakly-Weatherford field in Caddo County, Oklahoma, where working interests range from 1% to 26%. Production in these fields is from the Cleveland, Atoka, Morrow and Springer formations.

South Texas.    Our properties in South Texas produce primarily from the Vicksburg, Wilcox and Frio formations which range in depth from approximately 5,500 feet to 12,500 feet. The La Reforma field, located in Starr and Hidalgo Counties, is the largest field in the Wynn-Crosby property base. La Reforma is a significant Vicksburg formation field and we own between 25% and 50% working interest in this area. We are conducting an active drilling program at La Reforma with one well currently being completed, one well currently drilling, and four locations expected to be drilled in 2005. The Vicksburg formation in this area is complexly faulted and 3-D seismic is extensively utilized to identify optimal structural targets. Wells in this field typically produce at initial rates of over 10.0 Mmcfe per day. Other Vicksburg/Frio fields in which we own a significant interest include Los Indios, Nabors, Ann Mag and McAllen Ranch. In the Wilcox trend of Lavaca County, we own between 20% and 25% working interest in the Dry Hollow field, which produces from 12,500 to 15,000 feet in depth. At Dry Hollow, we have identified three proved undeveloped locations and one probable location, which we expect to drill in 2005. We also own interests in the Provident City and North Borchers fields in Lavaca County.

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Permian Basin.    In the Permian Basin, our principal properties are in the Waddell Ranch field in Crane County, Texas, the ROC field in Ward County, Texas, and the Teague field in Lea County, New Mexico. Waddell Ranch is the largest field in West Texas and produces primarily from the Grayburg, San Andres and Clear Fork formations at depths from 3,000 to 4,000 feet. We own a 3.5% working interest in this property. The ROC field produces from the Ellenberger and Montoya formations at measured depths of 13,000 to 17,000 feet. We have identified four proved undeveloped locations in this field, where we own a working interest of between 5% and 25%. In the Teague field, production is from the Devonian and Seven Rivers, Queen and Grayburg formations at a depth of 4,000 to 8,000 feet. We own a 94% working interest in this property and have identified two proved undeveloped locations.

East Texas.    Our properties in East Texas produce primarily from the Cotton Valley and Travis Peak formations which range in depth from approximately 6,500 to 10,000 feet. We own significant interests in the South Carthage, North Beckville and Blocker fields in Panola and Harrison Counties, Texas. Our working interest in these fields is between 47% and 100%. The producing formations of this area tend to contain multiple producing horizons and are typically low permeability sands that require fracture stimulation to achieve optimal producing rates. This type of fracture stimulation usually results in relatively high initial production rates that decline rapidly during the first year of production and subsequently stabilize at fairly low, more easily predictable annual decline rates. Much of our production in this area is from wells that have been producing for several years and are in the latter, more stable stage of production, resulting in a relatively long reserves to production ratio.

Arkoma Basin.    In the Arkoma Basin, our properties produce primarily from the Atoka formation at depths of 2,500 to 6,000 feet. We own significant interests in the Kinta, Cedars and Pine Hollow fields in Pittsburg and Haskell Counties, Oklahoma. Our working interest in these fields is between 23% and 100%. Portions of our acreage in this region are near the Pine Hollow South field, where a new shale gas drilling play is currently evolving. In addition, we own approximately 55,100 net undeveloped acres in Logan, Scott and Yell Counties, Arkansas.

Gulf Coast.    Our largest property in the Gulf Coast region is the West Broussard field, which is located in Lafayette Parish, Louisiana. In 2003, the Failla #1 well was drilled and completed, with the well being placed on production in September 2003. During 2004, the well produced approximately 15.0 gross Mmcf of natural gas and 350 gross barrels of oil per day. We have an approximate 9% working interest in this well. An additional development well, the Montesano #1, was drilled and completed during the third quarter of 2004. The well was placed on production in August 2004 and produced approximately 10.2 gross Mmcf of natural gas and 290 gross barrels of oil per day during the fourth quarter of 2004. We own a 23.1% working interest in this well, which will increase to approximately 29.6% working interest after payout.   The Montesano #1 is projected to reach payout during the fourth quarter of 2005.  The Failla #1 and Montesano #1 wells produce from the Bol Mex 3 formation at approximately 15,830 feet.

We also have properties in the Breton Sound/Main Pass area in Louisiana state waters, including a 25% working interest in 6 leased drilling prospects covering approximately 2,100 acres, as well as two producing wells, pipelines and associated production facilities.  We possess 79 square miles of recently reprocessed 3-D seismic data covering this area. The main objective formation is the Tex W at a depth of 11,500 feet. Wells in this area generally produce at high rates and are short lived.

We have between 5% and 12% working interest in the Ship Shoal 208/239 field located in federal waters, offshore Louisiana. In South Louisiana, we also own minor interests in the South Lake Arthur field, Vermilion Parish, which has produced over 1 Tcfe from the Myogyp formation. In addition, we own interests in Old Ocean, a large Frio formation field in Brazoria County, Texas.

Royalty Interest Properties.    At December 31, 2004, we own royalty interests in approximately 1,500 wells located in various oil and gas producing basins, producing an estimated 5.0 Mmcfe per day.  On February 25, 2005, we sold these properties for $80 million.  The agreement had an effective date of January 1, 2005.

Risk Management

From time to time, when we believe that market conditions are favorable, we use certain financial instruments called derivatives to manage price risks associated with our production.  While there are many different types of derivatives available, we primarily use natural gas and oil price swap and collar agreements to attempt to manage price risk more effectively.  The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place.  The collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period.  They provide for payments to counterparties if the index price exceeds the ceiling

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and payments from the counterparties if the index price is below the floor.  We will continue to evaluate the benefit of employing derivatives in the future.  See Item 7A Quantitative and Qualitative Disclosures about Market Risk.

NATURAL GAS AND CRUDE OIL OPERATIONS

Our principal properties consist of developed and undeveloped natural gas and oil leases and the reserves associated with these leases.  Generally, developed natural gas and oil leases remain in force so long as production is maintained.  Undeveloped natural gas and oil leaseholds are generally for a primary term of three to five years.  In most cases, the term of our undeveloped leases can be extended by paying delay rentals or by producing reserves that are discovered under those leases.  Our revolving credit facility is collateralized by our proved developed reserves associated with our oil and gas properties and gas gathering system.

The table below sets forth the results of our drilling activities for the periods indicated:

(1)           Although a well may be classified as productive upon completion, future production may deem the well to be uneconomical, particularly for exploration wells where there is little or no production history.

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We own interest in developed and undeveloped natural gas and oil acreage in the locations set forth in the table below.  These ownership interests generally take the form of working interest in natural gas and oil leases or licenses that have varying terms.  The following table presents a summary of our acreage interests as of December 31, 2004 and includes the recently acquired Wynn-Crosby and PHAWK properties.

At December 31, 2004, we had estimated proved reserves of approximately 161 Bcf of natural gas and 9,701 MBbls of oil.  These reserves are located entirely within the United States.  The following table sets forth, at December 31, 2004, these reserves.

For purposes of determining the above cash flows, estimates were made of quantities of proved reserves and the periods during which they are expected to produce in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a).  Future cash flows were computed by applying year-end prices to estimated annual future production from our proved oil and gas reserves.  The year-end prices for natural gas and crude oil used in the estimation were $6.18 per MMbtu, based on a December 31, 2004, Henry Hub spot market price and $40.25 per Bbl, based on a December 31, 2004, West Texas Intermediate posted price. These prices were adjusted by lease for quality or energy content, transportation fees and regional price differentials.  Future development and production costs were computed by applying year-end costs expected to be incurred in producing and further developing the proved reserves.  The estimated future net revenues were discounted using a 10% per annum discount factor.  The calculations assume the continuation of existing economic, operating and contractual conditions.  Other assumptions of equal validity could give rise to substantially different results.

For additional information on our natural gas and crude oil reserves, please refer to the supplementary natural gas and oil information.

We account for our natural gas and crude oil producing activities using the full cost method of accounting as prescribed by the SEC. Accordingly, all costs incurred in the acquisition, exploration, and development of proved natural gas and oil properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized.  All general corporate costs are expensed as incurred.  Sales or other dispositions of natural gas and oil properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change.  Depletion of evaluated natural gas and oil properties is computed on the units of production method based on all proved reserves on a country-by-country basis.  Unevaluated natural gas and oil properties are assessed quarterly for impairment either individually or on an aggregate basis.  The net capitalized costs of evaluated natural gas and oil properties are subject to a full cost ceiling limitation in which the costs, net of tax considerations, are not allowed to exceed their related estimated future net revenues discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, all net of tax considerations.

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Capitalized costs of our evaluated and unevaluated properties at December 31, 2004 and 2003 are summarized as follows:

Our natural gas and oil production volumes and average sales price are as follows:

The 2004 average natural gas and crude oil sales prices above do not reflect the impact of derivatives as these amounts are reflected as other income and expenses in the consolidated financial statements consistent with our decision not to elect hedge accounting in 2004.  The average natural gas and crude oil prices above for 2002 and 2003 reflect the impact of any hedges.  The 2003 average natural gas price was reduced by $0.59 per Mcf and average crude oil price was reduced by $1.80 per Bbl due to our hedges.  In 2002, the impact of hedges reduced our average natural gas price by $0.25 per Mcf and our average crude oil price by $1.76 per Bbl.

COMPETITIVE CONDITIONS IN THE BUSINESS

The natural gas and petroleum industry is highly competitive and we compete with a substantial number of other companies that have greater resources.  Many of these companies explore for, produce and market petroleum and natural gas, as well as, carry on refining operations and market the resultant products on a worldwide basis.  The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing natural gas and crude oil properties, and obtaining purchasers and transporters of the natural gas and crude oil we produce.  There is also competition between natural gas and petroleum producers and other industries producing energy and fuel.  Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and Canada; however, it is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations.  Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing natural gas and oil and may prevent or delay the commencement or continuation of a given operation.  The exact effect of these risk factors cannot be accurately predicted.

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OTHER BUSINESS MATTERS

Markets and Major Customers

In 2004, there were no individual customers accounting for more than 10% of our total sales.  In 2003 and 2002, approximately 53% and 54%, respectively, of our total sales were made to three individual customers.  We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce.  We believe other purchasers are available in our areas of operations.

Seasonality of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans.  Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices.  Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of results, which may be realized on an annual basis.

Operational Risks

Oil and gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome.  There is no assurance that we will discover or acquire additional oil and gas in commercial quantities.  Oil and gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other circumstances that may cause accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property may occur.  In such event, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could substantially reduce available cash and possibly result in loss of oil and gas properties.  Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities. We are not aware of any of these instances that have occurred to date that need to be accrued for.

As is common in the natural gas and crude oil industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive.  A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations.  For further discussion on risks see Item 7.      Management’s Discussion and Analysis of Financial Condition and Results of Operations.

REGULATIONS

Domestic exploration for, and production and sale of, natural gas and oil are extensively regulated at both the federal and state levels.  Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden.  Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas and oil industry that often are costly to comply with and that carry substantial penalties for failure to comply.  In addition, production operations are affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.

State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations.  Most states in which we operate also have statutes and regulations governing a number of environmental and conservation matters, including the unitization or pooling of natural gas and oil properties and establishment of maximum rates of production from natural gas and oil wells.  Many states also restrict production to the market demand for natural gas and oil.  Such statutes and regulations may limit the rate at which natural gas and oil and could otherwise be produced from our properties.

We are subject to extensive and evolving environmental laws and regulations.  These regulations are administered by the United States Environmental Protection Agency and various other federal, state, and local environmental, zoning, health and safety agencies, many of which periodically examine our operations to monitor compliance with such laws and regulations.  These regulations govern the release of waste materials into the environment, or otherwise relating to the protection of the environment, human, animal and plant health, and affect our operations and costs.  In recent years, environmental regulations have taken a cradle to grave approach to waste management, regulating and creating liabilities for the waste at its inception to final disposition.  Our natural gas and oil exploration, development and production operations are subject to numerous environmental programs, some of which include solid and hazardous waste management, water protection, air emission controls and situs controls affecting wetlands, coastal operations and antiquities.

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Environmental programs typically regulate the permitting, construction and operations of a facility.  Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit.  Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent.  Under appropriate circumstances, an administrative agency can request a cease and desist order to terminate operations.

New programs and changes in existing programs are anticipated, some of which include Natural Occurring Radioactive Materials, natural gas and oil exploration and production waste management and underground injection of waste materials.

Each state in which we operate has laws and regulations governing solid waste disposal, water and air pollution.  Many states also have regulations governing oil and gas exploration, development and production operations.

We are also subject to Federal and State Hazard Communications and Community Right to Know statutes and regulations.  These regulations govern record keeping and reporting of the use and release of hazardous substances.  We believe we are in compliance with these requirements in all material respects.

We may be required in the future to make substantial outlays to comply with environmental laws and regulations.  The additional changes in operating procedures and expenditures required to comply with future laws dealing with the protection of the environment cannot be predicted.

EMPLOYEES

As of December 31, 2004, we employed 43 full-time employees. We hire independent contractors on an as needed basis.  We have no collective bargaining agreements with our employees.  We believe that our employee relationships are satisfactory.

ACCESS TO COMPANY REPORTS

Our SEC filings are available to the public at the SEC’s web site at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference rooms located at 450 Fifth Street, N.W., Washington D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and their copy charges. In addition, through our website, www.petrohawk.com, you can access electronic copies of documents we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K and any amendments to those reports free of charge.  Access to those electronic filings is available as soon as practical after filing with the SEC.

CORPORATE GOVERNANCE  MATTERS

The Company’s Corporate Governance Guidelines, Code of Conduct, Nominating Committee Charter, Compensation Committee Charter and Audit Committee Charter are available on the Company’s website at www.petrohawk.com , under the Investor Relations section and a copy will be provided, without charge, to any shareholder upon request.

RISK FACTORS

Natural gas and crude oil prices are volatile, and low prices could have a material adverse impact on our business.

Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing natural gas and crude oil prices.  Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.&# 160; The amount we will be able to borrow under our revolving credit facility will be subject to periodic redetermination based in part on changing expectations of future prices.  Lower prices may also reduce the amount of natural gas and crude oil that we can economically produce and have an adverse effect on the value of our properties.

Prices for natural gas and crude oil have continued to remain high over the past twelve months.  Historically, the markets for natural gas and crude oil have been volatile, and they are likely to continue to be volatile in the future.  Among the factors that can cause volatility:

•                  the domestic and foreign supply of natural gas and crude oil;

•                  the ability of members of the Organization of Petroleum Exporting Countries (OPEC) and other producing countries to agree upon and maintain crude oil prices and production levels;

•                  political instability, armed conflict and terrorist attacks, whether or not in natural gas and crude oil producing regions;

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•                  the level of consumer product demand;

•                  the growth of consumer product demand in emerging markets, suc h as China;

•                  labor unrest in natural gas and oil producing regions;

•                  weather conditions;

•                  the price and availability of alternative fuels;

•                  the price of foreign imports;

•                  worldwide economic conditions; and

•                  the availability of liquid natural gas imports.

These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of natural gas and crude oil.

In general, the volume of production from natural gas and crude oil properties declines as reserves are depleted.  Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities.  Our future natural gas and crude oil production is highly dependent upon our level of success in finding or acquiring additional reserves.  However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.

The successful acquisition of producing properties requir es an assessment of a number of factors.  These factors include recoverable reserves, future natural gas and crude oil prices, operating costs and potential environmental and other liabilities, title issues and other factors.  Such assessments are inexact and their accuracy is inherently uncertain.  In connection with such assessments, we perform a review of the subject properties that we believe is thorough.  However, there is no assurance that such a review will reveal all existing or potential problems or allow us to fully assess the deficiencies and capabilities of such properties.  We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing natural gas and crude oil properties is particularly intense at this time and many of our competitors have financial and other resources which are substantially greater than those available to us.

Our bank lenders can limit our borrowing capabilities, which may materially impact our operations.

As of December 31, 2004, our total debt was $240 million and we had approximately $51 million of cash and additional available borrowing capacity under our revolving credit facility.  The borrowing base limitation under our revolving credit facility is semi-annually redetermined.  Redeterminations are based upon a number of factors, including commodity prices and reserve levels.  The next redetermination date is expected to occur in May 2005.  Upon a redetermination, we could be required to repay a portion of our bank debt.  We may not have sufficient funds to make such repayments, which could result in a default under the terms of the loan agreement and an acceleration of the loan.  We intend to finance our development, acquisition and exploration activities with cash flows from operations, bank borrowings and other financing activities.  In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties.  These changes in capitalization may significantly increase our level of debt.  If we incur additional debt for these or other purposes, the related risks that we now face could intensify.  A higher level of debt also increases the risk that we may default on our debt obligations.  Our ability to meet debt obligations and to reduce our level of debt depends on our future performance which is affected by general economic conditions and other financial and business factors.  Many of these factors are beyond our control .  Our level of debt affects our operations in several important ways, including the following:

•                  a portion of our cash flow from operations is used to pay interest on borrowings;

•                  the covenants  contained in the agreements governing our debt limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in business conditions;

•                  a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisition, general corporate or other purposes;

•                  a leveraged financial position would make us more vulnerable to economic downturns and could limit our ability to withstand competitive pressures; and

•                  any debt that we incur under our revolving credit facility will be at variable rates which makes us vulnerable to increases in interest rates.

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Our ability to finance our business activities will require us to generate substantial cash flow.

We may not be able to replace production with new reserves through our drilling or acquisition activities.

Our business activities require substantial capital. 0; We have budgeted total capital expenditures in 2005 of approximately $70 million.  We intend to finance our capital expenditures in the future through cash flows from operations, the incurrence of additional indebtedness and / or the issuance of additional equity securities.  We cannot be sure that our business will continue to generate cash flow at or above current levels.  Future cash flows and the availability of financing will be subject to a number of variables, such as:

•                  the level of production from existing wells;

•                  prices of natural gas and crude oil;

•                  our results in locating and producing new reserves;

•                  the success and timing of development of proved undeveloped reserves; and

•                  general economic, financial, competitive, legislative, regulatory and other factors beyond our control.

If we are unable to generate sufficient cash flow from operations to service our debt, we may have to obtain additional financing through the issuance of financial securities.  We cannot be sure that any additional financing will be available to us on acceptable terms.  Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders.  The level of our debt financing could also materially affect our operations.

If our revenues were to decrease due to lower natural gas and crude oil prices, decreased production or other reasons, and if we could not obtain capital through our revolving credit facility or otherwise, our ability to execute our development and acquisiti on plans, replace our reserves or maintain production levels could be greatly limited.

We may not be able to replace production with new reserves through our drilling or acquisition activities.

In general, the volume of production from natural gas and crude oil properties declines as reserves are depleted.  Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities.  Our future natural gas and crude oil production is highly dependent up on our level of success in finding or acquiring additional reserves.  However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.

The successful acquisition of producing properties requires an assessment of a number of factors.  These factors include recoverable reserves, future natural gas and crude oil prices, operating costs and potential environmental and other liabilities, title issues and other factors.  Such assessments are inexact and their accuracy is inherently uncertain.  In connection with such assessments, we perform a review of the subject properties that we believe is thorough.  ; However, there is no assurance that such a review will reveal all existing or potential problems or allow us to fully assess the deficiencies and capabilities of such properties.  We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing natural gas and crude oil properties is particularly intense at this time and many of our competitors have financial and other resources which are substantially greater than those available to us.

Drilling wells is speculative, often involves significant costs and may not result in additions to our production or reserves.

Developing and exploring for natural gas and crude oil reserves involves a high degree of operating and financial risk.  The actual costs of drilling, completing and operating wells often exceeds our budget for such costs and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services.  Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, mechanical difficulties, and faulty assumptions about geological features.  Moreover, the drilling of a productive natural gas and crude oil well does not ensure a profitable investment.  Exploratory wells bear a much greater risk of loss than development wells.  A variety of factors, including geological and market-related factors, can cause a well to become uneconomical or only marginally economic.  In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.

Estimates of natural gas and crude oil reserves are uncertain and inherently imprecise and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.

Our estimates of proved natural gas and crude oil reserves and the estimated future net revenues from such reserves are based upon various assumptions, including assumptions required by the SEC relating to natural gas and crude oil prices, drilling and operat ing expenses, capital expenditures, taxes and availability of funds.  The process of estimating natural gas and crude oil reserves is complex.  This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir.  Therefore, these estimates are inherently imprecise.

Actual future production, natural gas and crude oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and crude oil reserves will vary from those estimated.  Any significant variance could materially affect the estimated quantities and the value of our reserves.  Our properties may also be susceptible to hydrocarbon drainage from production by o ther operators on adjacent properties.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and crude oil prices and other factors, many of which are beyond our control.

At December 31, 2004, approximately 22% of our estimated proved reserves were undeveloped.  Estimates of undeveloped reserves are less certain than estimates of developed reserves.  Recovery of undeveloped reserves required significant capital expenditures and successful drilling operations.  The reserve data assumes that we will make significant capital expenditures to develop our reserves.  Although we have prepared estimates of these natural gas and crude oil reserves and the costs associated with development of these reserves in accordance with SEC regulations, we cannot assure you that the estimated costs or estimated reserves are accurate, that development will occur as scheduled or that the actual results will be as estimated.

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In addition, you should not construe our estimate of standardized measure of discounted future net cash flows relating to proved oil and gas reserves included in the Supplemental Oil and Gas Information as the current market value of the estimated oil and natural gas reserves attributable to our properties.  We have based the estimated discounted future net cash flows from proved reserve on prices and costs as of the date of the estimate, in accordance with applicable SEC regulations, whereas actual future prices and costs may be significantly higher or lower.  Many factors will affect future net cash flow, including:

&nb sp;

•                  prices of natural gas and crude oil;

•                  the amount and timing of actual production;

•                  the cost, timing and success in developing proved undeveloped reserves;

•                  supply and demand for natural gas and crude oil;

•  0;                curtailments or increases in consumption by natural gas and crude oil purchasers; and

•                  changes in governmental regulations or taxation.

The timing of the production of natural gas and crude oil properties and of the related expense a ffect the timing of actual future net cash flow from proved reserves and, thus, their actual value.  In addition, the 10% discount factor used is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business or the natural gas and crude oil industry in general are subject.

We depend on the skill, ability and decisions of third party operators to a significant extent.

We operate approximately 45% of our working interest estimated proved reserves.  The success of the drilling, development and production of the natural gas and crude oil properties in which we have or expect to have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties.  The failure of any third party operator to perform the following in a proper manner with respect to properties in which we have an interest could result in material adverse consequences to our interest in such properties, including substantial penalties and compliance costs:

•                  make decisions;

•                  perform their services;

•                  discharge their obligations;

•                  deal with regulatory agencies; and

•                  comply with laws, rules and regulations, including environmental laws and regulations.

Such adverse consequences could result in substantial liabilities to us or reduce the value of our properties, which could negatively affect our results of operations.

We depend substantially on the continued presence of key personnel for critical management decision and industry contacts.

Our management team changed significantly with the acquisition of control by PHAWK in May 2004.  We have six new directors, all new management, and many new technical personnel.  Our future performance will be substantially dependent on retaining key members of this group.  The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse affect on our business, operating results, financial condition and cash flows.  We currently do not have employment agreements with any of our employees.

Our business is highly competitive.

The natural gas and crude oil industry is highly competitive in many respects, including identification of attractive natural gas and crude oil properties for acquisition, exploration and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities.  In seeking suitable opportunities, we compete with a number of other companies, including large natural gas and crude oil companies and other independent operators with greater financial resources and, in some cases, with more expertise.  There can be no assurance that we will be able to compete effectively with these entities.

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Hedging transactions may limit our potential gains.

In order to manage our exposure to price risks in the marketing of our natural gas and crude oil production, we have entered into natural gas and crude oil price hedging arrangements with respect to a portion of our expected production.  We will most likely enter into additional hedging transactions in the future.  While intended to reduce the effects of volatile natural gas and crude oil prices, such transactions may limit our potential gains and increase our potential losses if natural gas and crude oil prices were to rise substantially over the price established by the hedge.  In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

•                  our production is less than expected;

•                  there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or

•                  the counterparties to our hedging agreements fail to perform under the contracts.

Our natural gas and crude oil activities are subject to various risks which are beyond our control.

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling natural gas and crude oil.  Although we may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances.  Many of these risks or hazards could materially and adversely affect our revenues and expenses, the ability of certain of our wells to produce natural gas and crude oil in commercial quantities, the rate of production and the economics of the development of, and our investment in, the prospects in which we have or will acquire an interest.  Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows.  Such risks and hazards include:

•                   human error, accidents, labor force and other factors beyond our control that may cause personal injuries or death to persons and destruction or damage to equipment and facilities;

•                   blowouts, fires, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment;

•                  unavailability of materials and equipment;

•                  engineering and construction delays;

•                  unanticipated transportation costs and delays;

•                  unfavorable weather conditions;

•                  hazards resulting from unusual or unexpected geological or environmental conditions;

•                  environmental regulations and requirements;

•                  accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment;

•                  changes in laws and regulations, including laws and regulations applicable to natural gas and crude oil activities or markets for the natural gas and crude oil produced;

•                  fluctuations in supply and demand for oil and gas causing variations of the prices we receive for our natural gas and crude oil production; and

•                  the internal and political decisions of OPEC and natural gas and crude oil producing nations and their impact upon natural gas and crude oil prices.

As a result of these risks, expenditures, quantities and rates of production, revenues and cash operating costs may be materially adversely affected and may differ materially from those anticipated by us.

Governmental and environmental regulations could adversely affect our business.

Our business is subject to federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of natural gas and crude oil and safety matters.  Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties and other matters.  These laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our natural gas and crude oil wells and other facilities.  In addition, these laws and regulations and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues.

Our operations are also subject to complex environmental laws and regulations adopted by the various jurisdictions in which we have natural gas and crude oil operations.  We could incur liability to governments or third parties for any unlawful discharge of natural gas, crude oil, or other pollutants into the air, soil or water, including responsibility for remedial costs. 

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We could potentially discharge these materials into the environment in any of the following ways:

•                  from a well or drilling equipment at a drill site;

•                  from gathering systems, pipelines, transportation facilities and storage tanks;

•                  damage to oil and natural gas wells resulting from accidents during normal operations; and

•                  blowouts, hurricanes, cratering and explosions.

Because the requirements imposed by laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business.  In addition, because we acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage caused by the former operators.

We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses which may be sustained in connection with all oil and gas activities.

We maintain general and excess liability policies, which we consider to be reasonable and consistent with industry standards.  These policies generally cover:

•                  personal injury;

•                  bodily injury;

•                  third party property damage;

•                  medical expenses;

•                  legal defense costs;

•                  pollution in some cases;

•                  well blowouts in some cases; and

•                  workers compensation.

There can be no assurance that this insurance coverage will be sufficient to cover every claim made against us in the future.  A loss in connection with our natural gas and crude oil properties could have a materially adverse effect on our financial position and results of operation to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.

Title to the properties in which we have an interest may be impaired by title defects.

We generally obtain title opinions on properties that we drill or acquire.  However, there is no assurance that we will not suffer a monetary loss from title defects or failure.  Generally, under the terms of the operating agreements affecting our properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property.  If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

We have not paid, and do not anticipate paying, any dividends on our common stock in the foreseeable future.

We have never paid any cash dividends on our common stock.  We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock.  Holders of our Series A preferred stock are entitled to receive cumulative dividends at the annual rate of $0.74 per share when and as declared by our board of directors.  No dividends may be paid on our common stock unless all cumulative dividends due on all of our Series A preferred stock have been declared and paid.  Our existing revolving credit facility restricts our ability to pay cash dividends on our preferred stock and common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict our ability to declare cash dividends on our preferred stock and common stock.

ITEM 2.  PROPERTIES

A description of our properties is included in Item 1. Business and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business.  We believe that our properties are adequate and suitable for the conduct of our business in the future.

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ITEM 3.  LEGAL PROCEEDINGS

None.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On November 23, 2004, we acquired Wynn-Crosby Energy, Inc. and eight of the limited partnerships it for a cash purchase price of approximately $425 million.  To finance a portion of the purchase price, we issued $200 million of our Series B 8% Automatically Convertible Preferred Stock (Series B preferred stock) to a group of qualified institutional buyers which were convertible into an approximate aggregate of 25,806,450 shares of our common stock. We obtained an additional $210 million in debt financing through a new revolving credit facility and a second-lien term loan facility with BNP Paribas as the lead bank and administrative agent. In order to accommodate the issuance of our common stock upon conversion of the Series B preferred stock, our board of directors approved an amendment to our certificate of incorporation to increase the number of our authorized shares of common stock from 50 million to 75 million shares. In addition, our board of directors approved an amendment to our 2004 Employee Incentive Plan to increase the aggregate number of shares that can be issued under the plan from 750,000 to 2,750,000.

PHAWK, LLC, which held a majority of our outstanding common stock at the time, approved the conversion of the Series B preferred stock into common stock, the amendment of our certificate of incorporation to increase our authorized shares of common stock from 50 million to 75 million shares and the amendment of our 2004 Employee Incentive Plan to increase the aggregate number of shares of common stock that may be issued under the plan to a total of 2,750,000, each by written consent as permitted by the Delaware General Corporation Law and our bylaws.  The action approved by PHAWK became effective on December 31, 2004, which was twenty days after we mailed an information statement to our shareholders describing the actions taken by written consent.

No other matters were submitted to a vote of our shareholders during the fourth quarter of the fiscal year ended December 31, 2004.

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PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our common stock began trading July 16, 2004 on the Nasdaq National Market under the symbol HAWK.  Prior to July 16, 2004, our common stock traded on the Nasdaq National Market under the symbol BETA.  The following table sets forth for the calendar periods indicated the high and low closing bid prices per share of our common stock as reported on the Nasdaq National Market.  The high and low bid amounts for periods prior to May 26, 2004 have been adjusted to reflect the one-for-two reverse split of our common stock effective on that date.  The bid information reflects inter-dealer prices, without retail markups, mark-downs, or commissions and may not necessarily represent actual transactions.

We have never paid cash dividends on our common stock.  We intend to retain earnings for use in the operation and expansion of our business and therefore do not anticipate declaring cash dividends on our common stock in the foreseeable future.  Holders of our Series A preferred stock are entitled to receive cumulative dividends at the annual rate of $0.74 per share when and as declared by the board of directors.  No dividends may be paid on common stock unless all cumulative dividends due on Series A preferred stock have been declared and paid.  Any future determination to pay dividends on common stock will be at the discretion of the board of directors and will be dependent upon then existing conditions, including our prospects, and such other factors, as the board of directors deems relevant.  We are also restricted from paying cash dividends on common stock under our credit facilities.

Approximately 209 shareholders of record as of February 2, 2005 held our common stock.  In many instances, a registered shareholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

A description of our equity compensation plan information is incorporated by reference from our definitive proxy statement to be filed with respect to our 2005 annual meeting under the heading Executive Compensation.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

We did not purchase any equity securities during the fourth quarter of 2004.  At December 31, 2004, we held 8,382 treasury shares.

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ITEM 6.  SELECTED HISTORICAL FINANCIAL DATA

The following tables presents selected historical financial data derived from our financial statements.  The following data is only a summary and should be read with our historical financial statements and related notes contained in this document.  The acquisition of Wynn-Crosby in 2004 and Red River Energy, Inc. in 2000 affects the comparability between the Financial Data for the periods presented.

(1)           On May18, 2004, the Company’s Board of Directors approved a one-for-two reverse stock split that was effective May 26, 2004.  The reverse stock split was implemented to effect the conditional approval by the NASDAQ National Market of the Company’s listing application, which was later formally approved.  As a result, all prior year common stock share amounts have been restated to reflect this reverse stock split in the chart above.

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ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in understanding our results of operations and our present financial condition.  Our consolidated financial statements and the accompanying notes included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.

Statements in this discussion may be forward-looking.  These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

Overview

Petrohawk Energy Corporation is an independent oil and gas company engaged in the acquisition, development, production and exploration of natural gas and crude oil.  Our exploration activities are concentrated in areas with known hydrocarbons resources, which are conducive to multi-well, repeatable drilling programs.

We have increased our proved reserves and production principally through acquisitions. We focus on properties within our core operating areas that have a significant proved reserve component and which management believes have additional development and exploration opportunities.

Our financial results depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production.  Commodity prices are affected by changes in market demands, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors.  As a result, we cannot accurately predict future natural gas and crude oil prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues.  In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.

At December 31, 2004, our estimated total proved oil and gas reserves were 219 billion cubic feet of natural gas equivalent (Bcfe), consisting of 161 billion cubic feet of natural gas and 9.7 million barrels of crude oil.  Proved reserves are approximately 73% natural gas on an equivalent basis and approximately 78% were classified as proved developed.  Year-end prices used to determine proved reserves were $6.18 per Mmbtu of gas and $40.25 per barrel of crude oil.

We have assembled an experienced management team and technical staff with significant experience and expertise in property acquisitions, development and divestments, reservoir engineering, production operations, exploration and financial management.  Most of the members of this team have worked together for several years with other companies.

We believe that our cash flow from operations and other financial resources will provide us with the ability to fully develop our existing properties, to finance our current exploration projects and to pursue new acquisition opportunities.

Capital Resources and Liquidity

Our primary source of cash in 2004 was from funds obtained from financing activities.  Proceeds from the issuance of long term debt and Series B preferred securities was offset by cash used in investing activities as the Company completed the acquisition of certain oil and gas properties from Wynn-Crosby as well as the acquisition of PHAWK, LLC.  In addition to these funds, the Company generated cash flows from the sale of natural gas and crude oil.  Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes.  Prices for natural gas and crude have historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout the recent years.  Working capital is substantially influenced by these variables.  Fluctuation in cash flow may result in an increase or decrease in our capital and exploration expenditures.  See Results of Operations for a review of the impact of prices and volumes on sales.  Cash flows provided by operating activities were primarily used to fund exploration and development expenditures.  See below for additional discussion and analysis of cash flow.

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Operating Activities.  Net cash provided by operating activities in 2004 increased $14 million from 2003.  This increase is primarily due to higher commodity prices and an increase in overall sales volumes in conjunction with the acquisitions discussed above in 2004.  Average realized prices increased 38% from $4.78 Mcfe in 2003 to $6.61 Mcfe in 2004.  Production volumes increased 91% from 2,632 Mmcfe to 5,030 Mmcfe.  We expect 2005 production to increase, but we are unable to predict future commodity prices.  As a result, we cannot provide any assurance about future levels of net cash provided by operating activities.

Net cash provided by operating activities in 2003 increased $1.4 million from 2002.  This increase was primarily due to a 52% increase in the average equivalent price per Mcfe.

Investing Activities.  The primary driver of cash used in investing activities is capital spending, inclusive of acquisitions.  We establish the budget for these amounts based on our current estimate of future commodity prices.  Due to the volatility of commodity prices, our budget may be periodically adjusted during any given year.  Cash used in investing activities in 2004 increased $398 million from 2003 to $402.  This increase was primarily driven by the acquisition of Wynn-Crosby of approximately $385 million, as well as the acquisition of certain natural gas and oil properties from PHAWK, LLC for approximately $3 million.  The remaining increase from prior year was due to an increase in overall capital spending and exploration costs of approximately $11 million.  In 2004, we drilled 71 gross wells compared to 28 in 2003.  Cash flows used in investing activities decreased from 2002 to 2003 due to a decrease in capital expenditures offset by a decrease in proceeds from sales of certain properties.

Financing Activities.  Net cash provided by financing activities in 2004 was $386 million compared to a use of $1 million in 2003.  Net cash provided by financing activities in 2004 was primarily driven by the following long-term debt issuances:

•                  In connection with the acquisition of Wynn-Crosby, we entered into a new revolving credit facility with BNP Paribas as the lead bank that is due in November 2008.  The revolving credit facility has an initial borrowing base of $200 million and a threshold amount of $180 million.  At December 31, 2004, $155 million is outstanding;

•                  A second lien facility in the amount of $50 million was also provided by BNP Paribas and a group of lenders that is due February 24, 2009.  At December 31, 2004, $50 million is outstanding; and

•                  In connection with the recapitalization of the Company by PHAWK, LLC, we issued a $35 million five-year unsecured subordinated convertible note payable to PHAWK, LLC.

The Company also received net proceeds of approximately $200 million for the issuance of 2,580,645 share of Series B 8% automatically convertible preferred stock in 2004.  The proceeds from this offering and the related financing transactions discussed above were used to fund a portion of the purchase price of Wynn-Crosby.

These cash receipts were offset by the repayment of long-term debt of $69 million, including approximately $41 million for the repayment outstanding long-term debt of Wynn-Crosby assumed in the closing of the transaction as well as the repayment of approximately $13 million of long-term debt upon the closing of the recapitalization of the Company in 2004.

During 2004, we paid $0.6 million in dividends on our Series A Preferred Securities.

Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including acquisitions.

Contractual Obligations

We have no material long-term commitments associated with our capital expenditure plans or operating agreements.  Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant.  Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, developmental and exploration activities, gas and oil price conditions and other related economic factors.  Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transaction with unconsolidated, limited-purpose entities.

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The following table summarizes our contractual obligations and commitments by payment periods.

(1)                                  Future interest expense was calculated based on interest rates and amounts outstanding at December 31, 2004 less required annual repayments.

Amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures.  The total amount of asset retirement obligations at December 31, 2004 is $12.7 million.

Senior Revolving Credit Facility

A senior revolving credit facility in the approximate amount of $400 million has been provided by BNP Paribas and a group of lenders. Availability under the revolver is restricted to the borrowing base. The initial borrowing base is $200 million, and is subject to review and adjustment on a semi-annual basis. Amounts outstanding under the revolver bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.25% to 2.50%. Such margins will fluctuate based on the utilization of the facility.  At December 31, 2004, we had a commitment fee of 0.38% on the unused portion of the initial borrowing base.  Borrowings under the revolver are secured by first priority liens on substantially all of our assets, including equity interests in subsidiaries. We are subject to certain financial covenants pertaining to minimum working capital levels, minimum coverage of interest expenses, and a maximum leverage ratio. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. All amounts drawn under the revolver are due and payable on November 23, 2008. At December 31, 2004, there were borrowings of $155 million on the senior revolving credit facility.

Second Lien Term Loan Facility

A second lien term loan facility in the amount of $50 million has been provided by BNP Paribas and a group of lenders. Any amounts repaid under the term loan may not be reborrowed. Borrowings under the term loan initially bear interest at LIBOR + 4.00%, increasing by 0.25% on a quarterly basis thereafter, subject to a ceiling of LIBOR + 5.00%. Borrowings under the term loan are secured by second priority liens on all of the assets (including equity interests) that secure the revolver. We are subject to certain financial covenants pertaining to a minimum asset coverage ratio and a maximum leverage ratio. In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We are obligated to repay 1% per annum of the original principal balance, with the remaining 96% of the original principal balance due and payable on February 24, 2009. At December 31, 2004, there were borrowings of $50 million under the second lien term loan facility.

Off-balance Sheet Arrangements

At December 31, 2004 and December 31, 2003, the Company did not have any off-balance sheet arrangements.

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Plan of Operation for 2005

On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations and, when necessary, our revolving credit facility.  We budget these capital expenditures based on our projected cash flows for the year.  We have budgeted $70 million in capital expenditures for 2005.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used.  Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements.  Described below are the most significant policies we apply in preparing our financial statements, some of which are subject to alternative treatments under generally accepted accounting principles. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with our audit committee. See Results of Operations above and Note 1, Organization and Summary of Significant Accounting Policies, to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Activities

Accounting for oil and gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and gas activities are available — successful efforts and full cost. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. The successful efforts method requires exploration costs to be expensed as they are incurred while the full cost method provides for the capitalization of these costs. Both methods generally provide for the periodic amortization of capitalized costs based on proved reserve quantities. Impairment of oil and gas properties under the successful efforts method is based on an evaluation of the carrying value of individual oil and gas properties against their estimated fair value, while impairment under the full cost method requires an evaluation of the carrying value of oil and gas properties included in a cost center against the net present value of future cash flows from the related proved reserves, using period-end prices and costs and a 10% discount rate.

Full Cost Method

We use the full cost method of accounting for our oil and gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into the cost centers (the amortization base) that are established on a country-by-country basis. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. Costs associated with production and general corporate activities are expensed in the period incurred. The capitalized costs of our oil and gas properties, plus an estimate of our future development and abandonment costs, are amortized on a unit-of-production method based on our estimate of total proved reserves. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas activities.

Proved Oil and Gas Reserves

Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the full cost ceiling limitation. Proved oil and gas reserves are the estimated quantities of natural gas and crude oil reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.

In 2004, all of the Company’s reserves, except 26.2 Bcfe related to royalty interest properties, were prepared by Netherland, Sewell & Associates, Inc., an independent oil and gas reservoir engineering consulting firm.  Additionally, in 2004, the

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Company did not have a significant reserve revision recorded.  For more information regarding reserve estimation, including historical reserve revisions, refer to Item 8 Consolidated Financial Statements and Supplementary Data, Supplemental Oil and Gas Disclosure.

Depreciation, Depletion and Amortization

The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depletion expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test write-down.

Full Cost Ceiling Limitation

Under the full cost method, we are subject to quarterly calculations of a ceiling or limitation on the amount of our oil and gas properties that can be capitalized on our balance sheet. If the net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test write-down to the extent of such excess. If required, it would reduce earnings and impact stockholders’ equity in the period of occurrence and result in lower amortization expense in future periods. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. However, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the quarter are held constant. However, we may not be subject to a write-down if prices increase subsequent to the end of a quarter in which a write-down might otherwise be required. If natural gas and oil prices decline, even if for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of our oil and gas properties could occur in the future.

Costs Withheld From Amortization

Unevaluated costs are excluded from our amortization base until we have evaluated the properties associated with these costs. The costs associated with unevaluated leasehold acreage and seismic data and wells currently drilling are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed quarterly for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred

In addition, a portion of incurred (if not previously included in the amortization base) and future development costs associated with qualifying major development projects may be temporarily excluded from amortization. To qualify, a project must require significant costs to ascertain the quantities of proved reserves attributable to the properties under development (e.g., the installation of an offshore production platform from which development wells are to be drilled). Incurred and future costs are allocated between completed and future work. Any temporarily excluded costs are included in the amortization base upon the earlier of when the associated reserves are determined to be proved or impairment is indicated.

Future Development and Abandonment Costs

Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, well depth, currently available procedures and ongoing consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. We review our assumptions and estimates of future development and future abandonment costs on an annual basis.

The accounting for future abandonment costs changed on January 1, 2003 with the adoption of SFAS No. 143. This new standard requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

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Holding all other factors constant, if our estimate of future abandonment and development costs is revised upward, earnings would decrease due to higher DD&A expense. Likewise, if these estimates are revised downward, earnings would increase due to lower DD&A expense.

Allocation of Purchase Price in Business Combinations

As part of our growth strategy, we actively pursue the acquisition of oil and gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. To the extent the consideration paid exceeds the fair value of the net assets acquired, we are required to record the excess as an asset called goodwill. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value allocated to the recoverable oil and gas reserves and unproved properties is subject to the cost center ceiling as described above.

Accounting for Derivative Instruments and Hedging Activities

Periodically, we utilize and may continue to utilize derivative instruments with respect to a portion of our natural gas and crude oil production to achieve a more predictable cash flow as well as to reduce our exposure to price fluctuations.  These transactions generally are price swaps or price collars and are entered into with commodities trading institutions.  Derivative financial instruments are intended to reduce the Company’s exposure to declines in the market price of natural gas and crude oil.

Stock Based Compensation

In accordance with current accounting standards, there are two alternative methods that can be used to account for stock-based compensation. The first method, the intrinsic value method, recognizes compensation cost as the excess, if any, of the quoted market price of our stock at the grant date over the amount an employee must pay to acquire the stock. Under the second method, the fair value method, compensation cost is measured at the grant date based on the value of an award and is recognized over the service period, which is usually the vesting period.  Currently, we use the fair value method as required by Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123) and related interpretations in accounting for our employee and director stock options.  See Item 8 Consolidated Financial Statements and Supplementary Data , Note 1 Summary of Significant Events and Accounting Polices for more information.

Forward-Looking Information

The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements.  The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements.  These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, and other factors detailed in this document and in our other Securities and Exchange Commission (SEC) filings.  If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document.

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Comparison of Results of Operations

Year Ended December 31, 2004 and Compared to Year Ended December 31, 2003

We had net income of $8.1 million for the year ended December 31, 2004 compared to $1.0 million for 2003.  The acquisition of Wynn-Crosby and the recapitalization by PHAWK, LLC as well as continued increases in natural gas and crude oil prices were the primary reasons for the increase in net income.

The following table summarizes key items of comparison and their related increase (decrease) for the year ended December 31 for the periods indicated.